One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.

Carbonate sediments are commonly formed in shallow, warm oceans either by direct precipitation out of seawater or by biological extraction of calcium carbonate from seawater to form skeletal material. The result is sediment composed of particles with a wide range of sizes and shapes mixed together to form a multitude of depositional textures. The sediment may be bound together by encrusting organisms or, more commonly, deposited as loose sediment subject to transport by ocean currents. A basic overview of carbonate-reservoir model construction was presented by Lucia,[1] and much of what is presented herein is taken from that book. Depositional textures are described using a classification developed by Dunham.[2] The Dunham classification divides carbonates into organically bound and loose sediments (see Figure 1). The loose sediment cannot be described in simple terms of grain size and sorting because shapes of carbonate grains can vary from spheroid ooids to flat-concave and high-spiral shells having internal pore space.

The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. Most often, residual oil saturation is measured; less frequently, connate water saturation (Swc) is the objective. Either saturation is measured where one phase effectively is stationary in the pore space (i.e., is at residual saturation) and the other phase can flow to the wellbore. Recently, the SWCT method has been extended to measure oil/water fractional flow at measured fluid saturations in situations in which both oil and water phases are mobile. The SWCT test is used primarily to quantify the target oil saturation before initiating improved oil recovery (IOR) operations, to measure the effectiveness of IOR agents in a single well pilot and to assess a field for bypassed oil targets.

Editor's Note: In 2011, the SPE R&D Committee identified five grand challenges facing the oil and gas industry. A series of articles focusing on each of these challenges was published in JPT in 2011 and 2012. This is a condensed version of a 2016 follow-up paper examining the current status of one of the grand challenges: carbon capture and sequestration. This collaborative paper is authored by steering committee and at-large members of the SPE Carbon Dioxide Capture and Utilization and the SPE R&D technical sections. Carbon capture and sequestration (CCS) is designed to reduce atmospheric emissions of greenhouse gases (GHGs).

Editor's Note: In 2011, the SPE R&D Committee identified five grand challenges facing the oil and gas industry. A series of articles focusing on each of these challenges was published in JPT in 2011 and 2012. This is a condensed version of a 2016 follow-up paper examining the current status of one of the grand challenges: carbon capture and sequestration. This collaborative paper is authored by steering committee and at-large members of the SPE Carbon Dioxide Capture and Utilization and the SPE R&D technical sections. Carbon capture and sequestration (CCS) is designed to reduce atmospheric emissions of greenhouse gases (GHGs).

As the application of Digital Rock Analysis (DRA) expands in industrial and academic settings, the need for digital investigation of more complex porous media, such as carbonates and tight rocks, has increased in the market. These materials exhibit a wide range of different mesoscale properties induced by their complex, multi-scale pore structures and their connectivity. The existence of complex pore space topology and wide pore size distributions requires computations to be done at high resolutions and in a large field of view. This means that the DRA of these samples must have three essential components of "parallel computing, multiscale modeling, and process-based reconstruction of 3D volumes." These are the three main pillars of Thermo Scientific e-Core Software, making it a unique solution for the characterization of more heterogeneous porous materials.

The efficient extraction of oil and gas requires that the reservoir be visualized in 3D space. Engineers need a conceptual model of reservoirs, an integral part of the decision-making process, whether it be selecting perforations or forecasting future production. However, most engineering measurements made on reservoirs have little or no spatial information. For example, a core measurement has no dimensional information, wireline logs and continuous core measurements are 1D, and production data and pressure information are volumetric but with unconstrained spatial information. Geologic information, on the other hand, contains valuable spatial information that can be used to visualize the reservoir in 3D space. Therefore, engineers should understand the geologic data that can improve their conceptual model of the reservoir and, thus, their engineering decisions. The first and most important geologic information is the external geometry of the reservoir, which is defined by seals or flow barriers that inhibit the migration of hydrocarbons, forming a hydrocarbon trap. The buoyancy force produced by the difference in density between water and hydrocarbons drives migration. Migration will cease, and a hydrocarbon reservoir will form, only where hydrocarbons encounter a trap. Traps are composed of top, lateral, and bottom seals; the geometry of traps can have structural, sedimentary, or diagenetic origins. The second most important geologic information is the internal reservoir architecture. A reservoir is composed of rock types of varying reservoir quality that are systematically stacked, according to stratigraphic and diagenetic principles.

For analysis of hydrocarbon potential, rocks are defined as aggregates or mixtures of minerals plus pores. Any analysis of the extent to which hydrocarbons are trapped in the formation and whether those hydrocarbons can be removed from the rock pores and produced has to begin with an analysis of the rocks themselves. There are three general rock types -- igneous, metamorphic, and sedimentary. Although hydrocarbon reservoirs have been found in all three rock types, this page will consider primarily sedimentary rocks, by far the most common rocks associated with hydrocarbons. Minerals are defined as naturally occurring solids; they have a definite structure, composition, and suite of properties that are either fixed or vary systematically within a definite range.

Reservoir models are constructed by distributing petrophysical properties in 3D space with geologic models as a template. Geologic models are constructed by distributing facies within a sequence stratigraphic framework using the systematic distribution of facies within a depositional model as a guide. There are many types of facies, and facies selection is normally based on the question to be answered. Water depth and changes in sea level are key questions when building a sequence stratigraphic model, and fossil and other grain types together with depositional textures are keys to estimating water depth. Thus, numerous "depositional" facies are commonly described from core material.

Summary With advancements in technology and computational capacity, the method of digital rock physics (DRP) for characterizing the storage and flow properties of a reservoir is gradually taking up the space that was once dominated by conventional methods such as routine core analysis (RCA) and special core analysis (SCAL). Unlike RCA and SCAL, the DRP method provides a nondestructive approach to deal with the core samples, which in a way is also more repeatable, economic, and is a clear improvement over the existing conventional methods in terms of its flexibility to experience the multiphysics of the rock and fluids. However, DRP still has some lacunae because the available algorithms have limitations in handling various challenges of complex lithology, such as grain/pore-boundary transition, soft/hard-matter transition, and imprints of intensity gradients of a 3D structure on 2D slices. Therefore, in this paper, we proposed a new approach to handle multiple issues by optimizing the segmentation algorithms and putting them together to standardize workflows (WFs) for reliable determination of the pore volume (PV), which could be verified with the field observation of porosity obtained using industry-standard laboratory methods and well logs. More emphasis was placed on the adaptability of the WF to deal with varying heterogeneity in the rocks. In this work, we proposed five WFs and compared them with the standard algorithms (including edge detections, watershed, and global thresholding) in terms of accuracy and computation time for a set of four homogeneous and four heterogeneous samples. We found that WF3 was the one that consistently performed better than all other WFs and some of the popular algorithms when compared one to one. We used a data-conditioning filter, contrast-limited adaptive histogram equalization (CLAHE)—a practice used in medical imagery—for local contrast enhancement in the heterogeneous carbonates to increase the signal/noise ratio of the rock-sample images. It successfully handled the contrast variability caused by the pockets of low illumination in the heterogeneous samples. Its limitation has also been detailed in the paper.